The present invention is preferably directed to the production of oil from subsurface deposits, primarily below 1,000 feet. Unlike systems used for the recovery of less viscous fluids, water by way of example, the recovery of oil is required to be accomplished from relatively deeper deposits, using significantly smaller diameter casing.
By way of example, water pumping systems, by virtue of the use of casing diameter of 12 inches and greater, are able to make practical use of higher RPM pumps, which are, by nature, larger in diameter. Moreover, because of the relatively shallow nature of such wells, such pumps are easily driven from a source of power located at the surface. This is because the drive shaft for transmitting motive power to a high revolution pump is coincidently shorter, and the amount of bearing support required is within practical limits. Clearly, the longer the drive shaft, the more bearing support required, with a commensurate increase in construction and maintenance costs.
Yet another distinguishable difference between oil and water wells is the inevitable presence of natural gas in an oil deposit, which is not found in water deposits. Oil wells accommodate gasses by using a conduit within the casing to relieve pressure and harvest the gasses. Remembering that oil well casings are typically less in diameter, the use of agricultural and other water recovery systems which are 12 inches and more, would be extremely difficult to adapt to oil production.
Mechanical lifting of oil from subsurface deposits is a common, indeed necessary, means of producing the world's hydrocarbon energy needs. The apparatus for accomplishing this needed task falls predominantly into five strategies or categories: rod pumping, gas lift, hydraulic pumping, electric submersible pumping,and progressive cavity pumping. Each type has its strong and weak points.
Rod pumping, the most common type of artificial lifting apparatus, consists of a piston type pump located downhole where it is submersed in the deposit in the well. The technique is to actuate the pump with a reciprocating rod string extending from the downhole pump to a pumping unit at the surface. This type of system is reliable, easily serviced, and satisfactory for most wells. However, rod pumping is not particularly well suited to deep, gassy, or abrasive fluid applications, i.e., where sand, salts and like particulate is found in the deposit, and has limited rate and depth capability due to the tensional strength limitations of the rod string.
Yet another problem with such systems becomes evident if a rod string breaks, and such is not uncommon. The cost in both time and effort to fish out the pump from the bottom of the well repair or replace the string, and return the pump to the appropriate depth, is high, yet borne regularly by those in the business, because there is no other way. The deeper the well, of course, the longer the string, and the greater the load on the string as it is reciprocated to operate the pump. Not surprisingly, the rate of failure of such strings is significantly higher.
Another fluid recovery system in wide use is referred to generally as a gas lift system and consists of injecting high pressure gas into a fluid filled tubing at depth, to lighten the fluid column, and cause the fluid to flow to the surface. Gas lift systems work well in moderate rate, moderate depth applications. It is insensitive to gassy or abrasive fluids, because the equipment is mechanically simple and inexpensive, and the systems are very reliable. Gas lift requires a source of gas, is energy inefficient, expensive to run and operate because of the compression requirements, and a poor option in low rate applications.
The currently preferred option for production of deep, low to moderate rate wells is referred to simply as hydraulic pumping. A typical system consists of a downhole piston pump which is connected to a downhole piston motor. The motor is actuated by high pressure hydraulic fluid injected down a string of tubing to the downhole pump-motor assembly. The reciprocating movement of the motor actuates the pump, which lifts the fluid in the deposit to the surface.
The tradeoff with hydraulic pumping is that hydraulic pumps are expensive to install and operate, and do not handle abrasive or gassy fluids well. They require high pressure hydraulic pumps at the surface, hydraulic fluid (usually crude oil) storage and treating facilities, and at least two strings of tubing.
Hydraulic jet pumps employ identical surface equipment and tubing requirements used in hydraulic pump systems such as described above, but replace the piston pump/motor assembly with a venturi-type jet assembly that uses Bernoulli's principle to "suck" the produced fluid into the stream of hydraulic fluid passing through the jet. The mix of hydraulic and produced fluid crude then flows up to the surface. Hydraulic jet pumps handle gassy fluids well, but are limited in the effective draw down they can generate and are energy inefficient.
A more recent approach to producing subsurface deposits has become available with the commercial exploitation of the progressive cavity pump.
Progressive cavity pumping (PCP) consists of a Moyno type pump downhole, which is actuated by a rod string that is rotated by a motor at the surface. PCPs are particularly well suited for delivering viscous, abrasive fluids. The surface and bottom hole equipment is simple and reliable, and energy efficiency is good. Progressive cavity pumps handle gas satisfactorily, but the system has depth and rate limitations and will mechanically fail if the volume of fluid entering the pump is less than what the pump can lift, and the well "pumps off".
The foregoing is intended to provide a pictorial view of a variety of production systems that have been, and continue to be, in use throughout oil producing countries.
By way of example, for high to very high rate applications, i.e., in excess of 1,000 barrels per day, there currently is only one generally accepted option for most field applications, and that is the electric submersible pumping (ESP). The ESP system consists of a multi-stage, downhole, centrifugal pump directly driven by a downhole electric motor.
Electric power for the motor is transmitted from the surface to the motor via an armored cable strapped to the tubing. ESPs offer a very wide range of rates and pumping depths, require a minimum of surface equipment (if a central electrical power source is available), and are reasonably energy efficient. They do not handle gassy or abrasive fluids well, and are rather inflexible with regard to varying rate capability of an installed unit. If power is not available at the well site, an electric generator driven by a gas or diesel engine is required.
ESPs, on the other hand, are typically expensive to purchase, service and operate, and with crude prices constantly in a state of flux, any system that can be cost effective is going to be of great value. The principal reason for the high cost of operating an ESP is the submersible electric motor. Because the motor must operate in a hot, saline water environment at high speeds and voltages, they are exotic and, hence, expensive to purchase and overhaul. ESPs are also very susceptible to power interruptions, have strict power interruptions, have a strict temperature limitation, and are the weak point of an otherwise excellent high volume lift system.
If a well environment is sandy, or contains abrasive or corrosive salts, friction at the pump is materially increased, with a commensurate increase in the load on the pump. If there are gas deposits in the area of the well, and it is not uncommon in deep wells, pumps, and particularly positive displacement pumps which are in common use, become highly inefficient, and proportionately more expensive to use.
The Geared Centrifugal Pumping system combines the high lift capacity of the ESP with the drive simplicity of the progressive cavity pumping system. Basically, the system consists of an electric motor and speed reducer at the surface, which turns a rod string connected to a speed increasing transmission/submersible downhole pump assembly (see generally FIG. 1). The speed reducer is needed at the surface because there is a limit to how fast a rod string can be turned stably. Experience with progressive cavity pumps has shown that rod string speeds of 500 RPM are about as fast as can be maintained reliably. The transmission increases the input rotational speed of the rod string from about 500 RPM to the 3,000 to 3,500 RPM needed to operate the submersible pump, which is attached to the bottom, output end of the transmission (see FIG. 1). Production enters the centrifugal pump inlet, flows up through the stages of the pump, flows around the transmission, and into the tubing, and up to the surface.
The GCP is similar in concept to the common agricultural submersible pumps, which are also driven by a surface motor turning a shaft that extends down to the multi-stage centrifugal pump downhole. In the agricultural application, there is no downhole transmission, as the motor, shaft and pump all turn at the some speed, about 1,600 RPM. They are able to turn the assembly this fast because the shaft is run inside a tubing string with stabilizing bearings run at 10 foot intervals, an impractical configuration for the much deeper oil wells.
An agriculture pump, running at only 1,600 RPM, is able to generate sufficient head per stage to lift water several hundred feet by virtue of the large diameter of the pump, made possible by the large diameter of the water wells (the head, or pressure each stage generates is proportional to the diameter of the pump rotor). Since oil wells typically have inside diameters in the 6 inch to 8 inch range, and oil wells are usually much deeper than water wells, ESPs typically run in the 3,000 to 3,500 RPM range to generate sufficient head per stage to keep the number of stages down to a manageable number (the head per stage is proportional also to the square of the rotational speed). Even at these high rpms, ESPs frequently will have 200+ stages to allow the lifting of fluid from several thousand feet.
The following patents represent some efforts to find a reliable, high capacity, deep well pumping system. The most common approach is still to use a downhole positive displacement pump driven by the rod string which is rotated or reciprocated by a surface power source.
Ortiz U.S. Pat. No. 3,891,031 is specifically directed to deep wells and a seal in the well casing which would permit the casing to become a part of the delivery system.
Justice U.S. Pat. No. 4,291,588 suggests a system for stripper wells, having bore diameters of about 4 inches. This specific patent addresses a step down transmission disposed between an electric motor and a positive displacement pump. It is presumed that other divisionals of the parent application address the system as a whole.
Garrison U.S. Pat. No. 4,108,023 addresses a step down transmission for use in a drill rig wherein drilling mud is capable of bypassing the transmission to lubricate the bit without invading the system itself.
Weber U.S. Pat. No. 5,209,294 is illustrative of a progressive cavity pump. Such pumps, however, operate at speeds from 300 to 1200 rpm, and their delivery rate is not optimum for deep well applications. A similar pump is shown in Cameron U.S. Pat. No. 5,275,238, although the essence of the patent is directed to objectives other than the pump per se.
It is also recognized that there are some higher speed applications in the agricultural field, that is in the neighborhood of 1200 to 1600 rpms, and typically driving a turbine pump. Unlike the present invention, however, these systems require that the drive shaft to the pump be encased, and bearings provided between the casing and the drive shaft to prevent the drive shaft from destruction during operation.
As will become apparent from a reading of the following description of the preferred embodiment of the present invention, none of the prior art efforts adequately address the practical problems long suffered by producers with respect to high rate deep wells. Despite the advantages of the above-noted devices, there remains a continuing need to improve on a deep well fluid recovery system.